System and method for monitoring volume and fluid flow of a wellbore

ABSTRACT

An apparatus for estimating a parameter of a borehole disposed in an earth formation, the system includes: an injection unit configured to inject at least one radio frequency identification device (RFID) into a fluid configured to be disposed in the borehole; and a collection unit configured to receive at least a portion of the fluid, the collection unit comprising a detector that detects at least one of the at least one RFID and data contents thereof; wherein the detector provides output for estimating the parameter. A method for estimating a parameter of a borehole is also disclosed.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of an earlier filing date from U.S.Provisional Application Ser. No. 61/119,843 filed Dec. 4, 2008, theentire disclosure of which is incorporated herein by reference.

BACKGROUND

During hydrocarbon drilling and recovery operations, a drilling fluid isinjected into a drillstring as a wellbore is drilled through an earthformation or through pre-existing equipment installed in that borehole.The drilling fluid or “mud” circulates through the drillstring, exitingthrough orifices, also known as “nozzles” or “jets”, into the wellboreannulus. That drilling fluid then passes from the bottom of the hole orexit point through the wellbore annulus between the wall of the hole andthe outside diameter of the drillstring and then onwards to the surfacewhere the returning fluid is recovered for treatment or disposal.

Material cut from the formation during drilling, known as drillcuttings, can be evaluated to determine various characteristics of thediscreet layers of the formation being penetrated, such as lithology,mineralogy including trace minerals, fossil or other organic content,petrophysical & geophysical characteristics, as well as any residualhydrocarbon, gas, or other fluid contents trapped in the pore space ofthe formation. In addition, the destruction of the formation by thedrill bit or other drilling and hole enlarging tools results in the porecontents of the formation being released into the mud as “mud gas”. Mudgas may be in liquid form under downhole pressure and temperatureconditions, but the liquid form may change to gaseous form during thetransition from the wellbore annulus to the atmospheric conditions atthe surface. Examples of “mud gas” include hydrocarbons, such as thealkanes including methane, ethane, propane and others; “acidic” gasessuch as carbon dioxide and hydrogen sulphide; and noble gases such ashelium, nitrogen, argon, etc. Other fluids trapped in the pore spaces ofthe formation such as oil and water, which may contain salts such aschlorides, may influence characteristics such as other chemicalcomponents, temperature, pressure, weight and viscosity of the mud. Suchevaluation of solids, liquids, gases and mud conditions is generallyreferred to as “mud logging”.

The volume of the wellbore annulus varies continuously while drillingprogresses due to planned and incidental variations in wellborediameter, changes in the drillstring configuration and its externaldiameters and lengths. The time to displace the contents of the wellboreannulus varies by the volumetric rate and location at which fluid ispumped into the drillstring, the quantity exiting the well and returningto the surface systems, the mud type and conditions, and anyinteractions between the solids, liquids and gases from the formationspenetrated or exposed in the wellbore, and the drilling fluid used todrill or complete the well. The individual times for solids, liquids andgases being displaced in a wellbore further varies by the density,shape, and surface and physio-chemical characteristics of the formationand the contents of its pore spaces.

Mud logging requires accurate knowledge of the annular volume in awellbore in order to accurately reconstruct the lithological andformation fluid components at the drill bit, based on samples which arerecovered over time from the drilling fluid at the surface. One methodof quantifying the annular volume involves the use of “tracers”, i.e.,non-reactive and detectable alien material inserted into the drillingfluid at the surface during a pumping operation. The tracer is movedfrom the drillstring annulus into the wellbore annulus and then returnsto the surface where it detected and/or recovered.

Current tracer technology involves adding a quantity of calcium carbidein the form of a “pill” that reacts to form acetylene in contact withwater, or adding a stream of acetylene or similar detectable alien gas,fluid or solid to the drilling fluid. The tracer is added at thesurface, and its return is identified using a mud logging gas detectionsystem or other sensors installed at the surface and in contact with thedrilling fluid. An annular volume is estimated from the time durationbetween injector to detector, and the resultant volume displaced by themud pumps during that duration. The tracers may be recycled over severaldisplacements of the annular volume until they become undetectable.However, this technique offers potential confusion about which tracersare actually being detected, compromising the accuracy of the volumeestimate.

SUMMARY

Disclosed is an apparatus for estimating a parameter of a boreholedisposed in an earth formation, the system includes: an injection unitconfigured to inject at least one radio frequency identification device(RFID) into a fluid configured to be disposed in the borehole; and acollection unit configured to receive at least a portion of the fluid,the collection unit comprising a detector that detects at least one ofthe at least one RFID and data contents thereof; wherein the detectorprovides output for estimating the parameter.

Also disclosed is a method of estimating a parameter of a boreholedisposed in an earth formation, the method includes: injecting at leastone radio frequency identification device (RFID) in a fluid configuredto be disposed in the borehole; circulating the fluid through theborehole and receiving at least a portion of the fluid in a collectionunit; detecting at least one of the at least one RFID device and datacontents thereof with a detector in the collection unit; and providingoutput from the detector for estimating the parameter.

BRIEF DESCRIPTION OF THE DRAWINGS

The following descriptions should not be considered limiting in any way.With reference to the accompanying drawings, like elements are numberedalike:

FIG. 1 depicts an embodiment of a well logging and/or drilling system;

FIG. 2 is a flow chart providing an exemplary method of measuring afluid volume through a borehole; and

FIG. 3 is an illustration of a system for measuring a fluid volumethrough a borehole.

DETAILED DESCRIPTION OF THE INVENTION

Referring to FIG. 1, an exemplary embodiment of a well logging and/ordrilling system 10 includes a drillstring 11 that is shown disposed in aborehole 12 that penetrates at least one earth formation 14 during adrilling, well logging and/or hydrocarbon production operation. Thedrillstring 11 includes a drill pipe, which may be one or more pipesections or coiled tubing. The well drilling system 10 also includes abottomhole assembly (BHA) 18. A borehole fluid 16 such as a drilling orcompletion fluid or drilling mud may be pumped through the drillstring11, the BHA 18 and/or the borehole 12. The drilling or completion fluidis liquid and/or gaseous.

As described herein, “borehole” or “wellbore” refers to a single holethat makes up all or part of a drilled well. As described herein,“formations” refer to the various features and materials that may beencountered in a subsurface environment. Accordingly, it should beconsidered that while the term “formation” generally refers to geologicformations of interest, that the term “formations,” as used herein, may,in some instances, include any geologic points or volumes of interest(such as a survey area). Furthermore, various drilling or completionservice tools may also be contained within this borehole or wellbore, inaddition to formations. In addition, it should be noted that“drillstring” as used herein, refers to any structure suitable forlowering a tool through a borehole or connecting a drill bit to thesurface, and is not limited to the structure and configuration describedherein. For example, the drillstring 11 is configured as a hydrocarbonproduction string.

In one embodiment, the BHA 18 includes a drilling assembly having adrill bit assembly 20 and associated motors adapted to drill throughearth formations. In one embodiment, the drill bit assembly 20 includesa steering assembly including a steering motor 22 configured torotationally control a shaft 24 connected to a drill bit or drillingtool 26. The shaft is utilized in drilling and milling operations tosteer the drill bit 26 and the drillstring 11 through the formation 14or through pre-existing drilling or completion service tools.

During drilling operations, the drilling fluid 16 is introduced into thedrillstring 11 from a mud tank or “pit” 28 or other source of drillingfluid 16, which may be liquid and/or gaseous, and is circulated underpressure through the drillstring 11, for example via one or more mudpumps. The drilling fluid 16 passes into the drillstring 11 and isdischarged at the bottom of the borehole through an opening in the drillbit or drilling tool 26. The drilling fluid 16 circulates uphole betweenthe drill string 11 and the borehole 12 and is discharged into, forexample, the mud tank 28 via a return flow line 30.

The system 10 includes a tracer system for calculating a circulationtime of the drilling fluid 16 through the borehole 12, which is in turnutilized to calculate the fluid volume. In one embodiment, an effectivevolume of the drillstring 11 and the borehole 12 is calculated using thetime duration taken from injection to detection and the volume displacedby the mud pumps during that duration. As used herein, the fluid mayinclude drilling fluid 16 which may be liquid or gaseous, as well as anycombination of gases, hydrocarbons and cuttings or millings from thedrill bit and the formation 14, and is accordingly referred to hereafteras “borehole fluid” 16.

The tracer system includes an injection unit 32 including at least oneRadio Frequency Identification Device (“RFID”) 34. The RFID 34 has knowncharacteristics and may potentially be a plurality of RFIDs of the sameor different sizes. The injection unit 32, in one embodiment, isdisposed at a surface location, such as in fluid communication with asuction tank included in a drilling rig connected to the drillstring 11.In other embodiments, the injection unit 32 is configured to inject theRFID 34 at any selected location along the length of the drillstring 11.

In one embodiment, the RFID 34 is in the nano-scale. In anotherembodiment, the RFID 34 is a microelectromechanical system device(“MEMS”) incorporated in a MEMS system. For example, a MEMS systemincludes a plurality of MEMS devices each incorporating an RFID 34. SuchMEMS particles are referred to as “smart dust”. Using a plurality ofRFIDs 34, such as in a smart dust system, with different signatures andparticle sizes enables a more complete annular profile and displacementrates to be mapped.

In one embodiment, the MEMS devices are sensors configured to measurephysico-chemical properties of the drillstring 11, the borehole 12and/or the formation 14, and carry data corresponding to theseproperties to a surface detection system. Examples of suchphysico-chemical properties include pressure, temperature and chemicalcomposition.

In one embodiment, the MEMS devices or smart dust are incorporated intoa fluid additive configured to be injected into a drilling or completionfluid or other borehole fluid. In this embodiment, the smart dust isincluded in the fluid additive prior to injection into the boreholefluid.

The tracer system further includes a collection unit 36 that receives atleast a portion of the borehole fluid 16. A detector 38 is disposedwithin the collection unit 36 and includes an antenna and suitableelectronics to emit an electromagnetic detection signal into theborehole fluid 16. In one embodiment, the detector 38 is disposed at anysuitable location, such as on the return flow line 30. In thisembodiment, the collection unit 36 forms a portion of the return flowline 30, and the detector detects the RFID 34 as it passes through thereturn flow line 30.

Each RFID 34 includes a processing chip or other electronics unit and anantenna configured to receive the detection signal and emit a returnsignal identifying the RFID 34. For example, each RFID 34 is programmedwith a unique identification number or batch number that is sent to thedetector 38 in the return signal. The data associated with the returnsignal, in one embodiment, is transmitted to a suitable processor suchas a surface processing unit 40. The processor identifies the detectedRFID 34, calculates a circulation time from the difference between thetime that the RFID 34 is injected into the drilling fluid 16 and thetime that the RFID 34 is detected.

In one embodiment, the tracer system and/or the BHA 18 are incommunication with the surface processing unit 40. In one embodiment,the surface processing unit 40 is configured as a surface drillingcontrol unit which controls various production and/or drillingparameters such as rotary speed, weight-on-bit, fluid flow parameters,pumping parameters and others and records and displays real-timedrilling performance and/or formation evaluation data. In addition, thesurface processing unit may be configured as a tracer system controlunit and control the injection of the RFID 34 remotely. The BHA 18and/or the tracer system incorporates any of various transmission mediaand connections, such as wired connections, fiber optic connections,wireless connections and mud pulse telemetry.

In one embodiment, the surface processing unit 40 includes components asnecessary to provide for storing and/or processing data collected fromthe injection unit 32 and/or the collection unit 36. Exemplarycomponents include, without limitation, at least one processor, storage,memory, input devices, output devices and the like.

The BHA 18, in one embodiment, includes a downhole tool 42. In oneembodiment, selected components of the tracer system are incorporatedinto the downhole tool 42, such as the injection unit 32, to allow thetravel time of the fluid between the drill bit assembly 20 and thesurface to be calculated.

In one embodiment, the downhole tool 42 includes one or more sensors orreceivers 44 to measure various properties of the borehole environment,including the formation 14 and/or the borehole 12. Such sensors 44include, for example, nuclear magnetic resonance (NMR) sensors,resistivity sensors, porosity sensors, gamma ray sensors, seismicreceivers and others. Such sensors 44 are utilized, for example, inlogging processes such as measurement-while-drilling (MWD) andlogging-while-drilling (LWD) processes.

Although the tracer system is described in conjunction with thedrillstring 11, the tracer system may be used in conjunction with anystructure suitable to be lowered into a borehole, such as a productionstring or a wireline.

FIG. 2 illustrates a method 50 of measuring a fluid volume through aborehole. The method 50 is used in conjunction with the tracer systemand the surface processing unit 40, although the method 50 may beutilized in conjunction with any suitable combination of processors andsystems incorporating RFID devices. The method 50 includes one or morestages 51, 52, 53, 54 and 55. In one embodiment, the method 50 includesthe execution of all of stages 51-55 in the order described. However,certain stages may be omitted, stages may be added, or the order of thestages changed.

In the first stage 51, the drillstring 11 is introduced into theborehole 12 and borehole fluid 16 is introduced into the drillstring 11.

In the second stage 52, at least one RFID 34 is injected into theborehole fluid 16 from the injection unit 32. A location and time of theinjection is noted and, in one embodiment, transmitted to a suitableprocessor.

In the third stage 53, the borehole fluid 16 is circulated through thedrillstring 11 and returns to the surface through the borehole 12. Aportion of the borehole fluid 16 is collected by the collection unit 36.At this point, the borehole fluid 16 may include drill bit cuttings,water, gas, hydrocarbons, formation material and/or other materials.

In the fourth stage 54, the RFID 34 is detected in the collection unit36. In one embodiment, the time of detection is noted and transmitted tothe processor.

In the fifth stage 55, a circulation time between injecting the at leastone RFID 34 and detecting the at least one RFID 34 is calculated, and aborehole fluid volume is calculated based on the circulation time. Thisvolume may include the volume of fluid within the drillstring 11 and/orthe annular volume of fluid between the drillstring 11 and the walls ofthe borehole 12. For example, if the flow rate of fluid introduced intothe borehole 12 is known, such as the volumetric flow of fluid through amud pump, the circulation time of the RFID 34 is used to determine atotal fluid volume in the borehole 12.

Referring to FIG. 3, there is provided a system 60 for measuring thetime taken for a fluid volume to be displaced through a borehole and/orcalculating a volume of the drillstring 11 and/or the wellbore 12. Thesystem may be incorporated in a computer 61 or other processing unitcapable of receiving data from the injection unit 32 and/or the detector38. Exemplary components of the system 60 include, without limitation,at least one processor, storage, memory, input devices, output devicesand the like. As these components are known to those skilled in the art,these are not depicted in any detail herein.

Generally, some of the teachings herein are reduced to instructions thatare stored on machine-readable media. The instructions are implementedby the computer 61 and provide operators with desired output.

The systems and methods described herein provide various advantages overprior art techniques. In contrast to calcium carbide tracers, thetracers described herein do not need to be introduced on a well rigfloor, and can rather be introduced into a rig's suction tank or fromdownhole sources within the drillstring or bottom hole assemblyautomatically and/or remotely without the need for human manualintervention. In addition, tracers described herein can bedifferentiated by size, physical characteristics or electroniccharacteristics, eliminating any confusion as to which tracers are beingdetected. These tracers may also be able to measure and carry data toreflect the ambient environment through which they have passed.

In support of the teachings herein, various analyses and/or analyticalcomponents may be used, including digital and/or analog systems. Thesystem may have components such as a processor, storage media, memory,input, output, communications link (wired, wireless, pulsed mud, opticalor other), user interfaces, software programs, signal processors(digital or analog) and other such components (such as resistors,capacitors, inductors and others) to provide for operation and analysesof the apparatus and methods disclosed herein in any of several mannerswell-appreciated in the art. It is considered that these teachings maybe, but need not be, implemented in conjunction with a set of computerexecutable instructions stored on a computer readable medium, includingmemory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, harddrives), or any other type that when executed causes a computer toimplement the method of the present invention. These instructions mayprovide for equipment operation, control, data collection and analysisand other functions deemed relevant by a system designer, owner, user orother such personnel, in addition to the functions described in thisdisclosure.

Further, various other components may be included and called upon forproviding aspects of the teachings herein. For example, a sample line,sample storage, sample chamber, sample exhaust, filtration system, pump,piston, power supply (e.g., at least one of a generator, a remote supplyand a battery), vacuum supply, pressure supply, refrigeration (i.e.,cooling) unit or supply, heating component, motive force (such as atranslational force, propulsional force or a rotational force), magnet,electromagnet, sensor, electrode, transmitter, receiver, transceiver,controller, optical unit, electrical unit or electromechanical unit maybe included in support of the various aspects discussed herein or insupport of other functions beyond this disclosure.

Elements of the embodiments have been introduced with either thearticles “a” or “an.” The articles are intended to mean that there areone or more of the elements. The terms “including” and “having” andtheir derivatives are intended to be inclusive such that there may beadditional elements other than the elements listed. The conjunction “or”when used with a list of at least two terms is intended to mean any termor combination of terms.

One skilled in the art will recognize that the various components ortechnologies may provide certain necessary or beneficial functionalityor features. Accordingly, these functions and features as may be neededin support of the appended claims and variations thereof, are recognizedas being inherently included as a part of the teachings herein and apart of the invention disclosed.

While the invention has been described with reference to exemplaryembodiments, it will be understood by those skilled in the art thatvarious changes may be made and equivalents may be substituted forelements thereof without departing from the scope of the invention. Inaddition, many modifications will be appreciated by those skilled in theart to adapt a particular instrument, situation or material to theteachings of the invention without departing from the essential scopethereof. Therefore, it is intended that the invention not be limited tothe particular embodiment disclosed as the best mode contemplated forcarrying out this invention, but that the invention will include allembodiments falling within the scope of the appended claims.

1. An apparatus for estimating a parameter of a borehole disposed in anearth formation, the system comprising: an injection unit configured toinject at least one radio frequency identification device (RFID) into afluid configured to be disposed in the borehole; and a collection unitconfigured to receive at least a portion of the fluid, the collectionunit comprising a detector that detects at least one of the at least oneRFID and data contents thereof; wherein the detector provides output forestimating the parameter.
 2. The apparatus of claim 1, furthercomprising a processor in operable communication with at least one ofthe injection unit and the detector, the processor configured tocalculate a circulation time between injection of the at least one RFIDinto the borehole fluid and detection of the at least one RFID by thedetector and to calculate a volume of the borehole.
 3. The apparatus ofclaim 1, wherein the collection unit is located at a surface location.4. The apparatus of claim 1, wherein the at least one RFID is aplurality of RFIDs.
 5. The apparatus of claim 4, wherein each RFID inthe plurality is a microelectromechanical system (MEMS) device.
 6. Theapparatus of claim 4, wherein each RFID in the plurality is configuredto emit a unique identification signal to the detector.
 7. The apparatusof claim 1, wherein the injection unit is disposed in at least one of asurface location and a downhole location.
 8. The apparatus of claim 1,further comprising a bottomhole assembly (BHA) including a drill bitassembly, the bottomhole assembly incorporating the injection unittherein.
 9. The apparatus of claim 1, wherein the parameter is anannular volume between a borehole assembly and the borehole, theborehole assembly being configured to be disposed along a length of theborehole and to receive the fluid therein.
 10. The apparatus of claim 1,further comprising a return conduit located at a surface location and influid communication with an annular portion of the borehole.
 11. Theapparatus of claim 10, wherein the collection unit forms a selectedportion of the return conduit and the detector is disposed on theselected portion.
 12. The apparatus of claim 1, wherein the collectionunit comprises an antenna and an electronics unit configured to emit anelectromagnetic detection signal into the collection unit.
 13. Theapparatus of claim 12, wherein the at least one RFID comprises aprocessing unit and an antenna configured to receive the detectionsignal and emit a return signal identifying the at least one RFID anddata contents thereof.
 14. A method of estimating a parameter of aborehole disposed in an earth formation, the method comprising:injecting at least one radio frequency identification device (RFID) in afluid configured to be disposed in the borehole; circulating the fluidthrough the borehole and receiving at least a portion of the fluid in acollection unit; detecting at least one of the at least one RFID anddata contents thereof with a detector in the collection unit; andproviding output from the detector for estimating the parameter.
 15. Themethod of claim 14, further comprising introducing a drillstring intothe borehole and introducing the fluid into the drillstring.
 16. Themethod of claim 15, wherein circulating comprises circulating the fluidthrough the drillstring and the borehole.
 17. The method of claim 14,further comprising measuring a circulation time between injecting the atleast one RFID and detecting the at least one RFID and estimating avolume of the borehole using the circulation time.
 18. The method ofclaim 17, wherein the volume is an annular volume between thedrillstring and the borehole.
 19. The method of claim 14, wherein the atleast one RFID device is injected at a location selected from at leastone of a surface location and a downhole location.
 20. The method ofclaim 14, wherein the collection unit is in fluid communication with areturn conduit located at a surface location and in fluid communicationwith an annular portion of the borehole.
 21. The method of claim 20,wherein the detector is disposed on a portion of the return conduit. 22.The method of claim 14, wherein the detecting comprises emitting anelectromagnetic detection signal into the collection unit and causingthe at least one RFID device to emit a return signal for identifying atleast one of the at least one RFID and the data contents thereof.